Methods of drilling and consolidating subterranean formation particulate

ABSTRACT

Improved methods for drilling well bores penetrating producing zones while controlling formation particulates are provided. Some embodiments provide methods of drilling a well bore into a subterranean formation comprising the steps of providing a drilling composition comprising a drilling fluid and a consolidating material; and, using the drilling composition while drilling the well bore and allowing the consolidating material in the drilling composition to penetrate into the walls of the well bore.

FIELD OF THE INVENTION

The present invention describes improved methods for drilling andtreating well bores. More particularly, the present invention relates toimproved methods for drilling well bores penetrating producing zoneswhile controlling formation particulates.

DESCRIPTION OF THE PRIOR ART

Often, well bores are drilled into weakly consolidated formationswherein the walls of the well bore may be sensitive to degradation bythe force of mobile fluids within the formation. Often, such well boresare subjected to some form of sand control operation such as gravelpacking to reduce the migration of unconsolidated formationparticulates. One common gravel packing operation involves placing agravel pack screen in the well bore and packing the surrounding annulusbetween the screen and the well bore with particulates referred to as“gravel” that have a specific size designed to prevent the passage offormation sand. The gravel pack screen is generally a filter assemblyused, inter alia, to support and retain the gravel placed during gravelpack operations. A wide range of sizes and screen configurations areavailable to suit the characteristics of the gravel pack sand used.Similarly, a wide range of sizes of gravel is available to suit thecharacteristics of the unconsolidated or poorly consolidatedparticulates in the subterranean formation. The resulting structurepresents a barrier to migrating sand from the formation while stillpermitting fluid flow. When installing the gravel pack, the gravel iscarried to the formation in the form of a slurry by mixing the gravelwith a transport fluid. Gravel packs act, inter alia, to stabilize theformation while causing minimal impairment to well productivity. Thegravel, inter alia, acts to prevent the particulates from occluding thescreen or migrating with the produced fluids, and the screen, interalia, acts to prevent the gravel from entering the production tubing.While gravel packs have been successfully used to control the migrationof formation sands, their placement generally reduces the availablediameter of a well bore due to the physical size of the screen and theresulting gravel annulus.

The screen assembly referred to in the gravel packing operation may alsobe used as an independent sand control means. Some of the early screentechnology dictated that the screens had to be small enough to passthrough the smallest diameter of the well bore on the way to its desiredplacement location where the diameter of the well bore may actually belarger. Developments in technology have lead to deformable andexpandable screens such that a relatively small size or small diameterscreen may be placed in a desired location along the well bore and thenexpanded to accommodate the actual size of the well bore at the point ofplacement.

While the sand control methods mentioned above are routinely used in thecompletion of well bores, particularly those drilled into weaklyconsolidated formations, they increase the expense of installing a wellbore by requiring separate steps to drill the well bore and then tocontrol the formation sands.

SUMMARY OF THE INVENTION

The present invention describes improved methods for drilling andtreating well bores. More particularly, the present invention relates toimproved methods for drilling well bores penetrating producing zoneswhile controlling formation particulates.

Some embodiments of the present invention provide methods of drilling awell bore into a subterranean formation comprising the steps ofproviding a drilling composition comprising a drilling fluid and aconsolidating material; and, using the drilling composition whiledrilling the well bore and allowing the consolidating material in thedrilling composition to penetrate into the walls of the well bore.

Other embodiments of the present invention provide methods ofconsolidating a subterranean formation surrounding a well borecomprising the steps of providing a drilling composition comprising adrilling fluid and a consolidating material; and, using the drillingcomposition while drilling the well bore and allowing the consolidatingmaterial in the drilling composition to penetrate into the walls of thewell bore as it is formed.

Other and further objects, features and advantages of the presentinvention will be readily apparent to those skilled in the art upon areading of the description of preferred embodiments which follows.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention describes improved methods for drilling andtreating well bores. More particularly, the present invention relates toimproved methods for drilling well bores penetrating producing zoneswhile controlling formation particulates.

In some embodiments of the methods of the present invention, a well boreis drilled with a drilling composition comprising a drilling fluid and aconsolidating material. The consolidating material is allowed topenetrate into the formation and substantially cure, thus consolidatingthe formation sands along the wall of the well bore. The methods of thepresent invention provide, inter alia, a means for stabilizing weaklyconsolidated formations surrounding a well bore during drilling,preventing the formation from collapsing during production, andproducing through the treated interval.

Drilling fluids suitable or use in the present invention may bewater-based fluids or oil-based invert emulsion fluids. Essentially anydrilling fluid suitable for a drilling application may be used inaccordance with the present invention, including aqueous gels,emulsions, and other suitable fluids. Suitable aqueous gels aregenerally comprised of water and one or more gelling agents and mayfurther comprise weighting agents. Suitable emulsions may be comprisedof two immiscible liquids such as an aqueous gelled liquid and aliquefied, normally gaseous fluid, such as nitrogen. In some embodimentsof the present invention where the well bore is drilled into a producingzone, the drilling fluid may comprise a drill-in fluid, which is a fluiddesigned specifically for drilling through the reservoir section of awell bore. Drill-in fluids are often used, inter alia, to minimizedamage and maximize production of exposed zones and to facilitate laterwell completion procedures. Often, additives essential for fluid losscontrol and cuttings carrying are present in a drill-in fluid. It iswithin the ability of one skilled in the art, with the benefit of thisdisclosure, to select a drilling fluid suitable for use in the drillingcompositions of the present invention.

Traditional drilling operations add solid particulate matter to thedrilling fluid to help control fluid loss to the surrounding formation.In the methods of the present invention, use of such additives can begreatly reduced or eliminated due to the fact that the consolidationmaterial added to the drilling fluid may act as a fluid loss controlagent. Thus, drilling compositions suitable for use in the presentinvention preferably comprise only a small amount of particulate fluidloss control material. In some embodiments of the present invention,particularly in those applications where the formation being drilled hasa low permeability, e.g. a chalk formation, the drilling fluidcomposition may contain little if any particulate fluid loss controlmaterial. In other embodiments of the present invention, a fluid losscontrol material is present in the drilling fluid composition in anamount ranging from 0.1% to about 10% by weight of the overall drillingfluid composition. When used, the particulate fluid loss controlmaterial is preferably a material that will degrade in the well bore.Suitable such degradable fluid loss control material's include, but arenot limited to, aliphatic polyesters, polylactic acid, poly(lactides),poly(orthoesters) and combinations thereof.

Consolidation materials suitable for use in the present inventioninclude, but are not limited to, low-temperature epoxy-based resins,furan-based resins, phenolic-based resins, high-temperature (HT)epoxy-based resins, and phenol/phenol formaldehyde/furfuryl alcoholresins.

The temperature of the subterranean formation being drilled may affectselection of a consolidation material. By way of example, forsubterranean formations exhibiting a temperature ranging from about 60°F. to about 250° F., low-temperature epoxy-based resins comprising ahardenable resin component and a hardening agent component containingspecific hardening agents may be preferred. For subterranean formationsexhibiting a temperature ranging from about 300° F. to about 600° F., afuran-based resin may be preferred. For subterranean formationsexhibiting a temperature ranging from about 200° F. to about 400° F.,either a phenolic-based resin or a HT epoxy-based resin may be suitable.For subterranean formations exhibiting a temperature of at least about175° F., a phenol/phenol formaldehyde/furfuryl alcohol resin may also besuitable.

One consolidation material suitable for use in the methods of thepresent invention is a low-temperature epoxy based resin comprising ahardenable resin component and a hardening agent component. Thehardenable resin component is comprised of a hardenable resin and anoptional solvent. The solvent may be added to the resin to reduce itsviscosity for ease of handling, mixing and transferring. It is withinthe ability of one skilled in the art with the benefit of thisdisclosure to determine if and how much solvent may be needed to achievea viscosity suitable to the subterranean conditions, e.g. a low enoughviscosity to permeate into the formation being drilled. Factors that mayaffect this decision include geographic location of the well and thesurrounding weather conditions. An alternate way to reduce the viscosityof the liquid hardenable resin is to heat it. This method avoids the useof a solvent altogether, which may be desirable in certaincircumstances. The second component is the liquid hardening agentcomponent, which is comprised of a hardening agent, a silane couplingagent, a surfactant, an optional hydrolyzable ester for, inter alia,breaking gelled fracturing fluid films on the proppant particles, and anoptional liquid carrier fluid for, inter alia, reducing the viscosity ofthe liquid hardening agent component. It is within the ability of oneskilled in the art with the benefit of this disclosure to determine ifand how much liquid carrier fluid is needed to achieve a viscositysuitable to the subterranean conditions.

Examples of hardenable resins that can be utilized in the liquidhardenable resin component include, but are not limited to, organicresins such as bisphenol A-epichlorohydrin resins, polyepoxide resins,novolak resins, polyester resins, phenol-aldehyde resins, urea-aldehyderesins, furan resins, urethane resins, glycidyl ethers and mixturesthereof. The resin utilized is included in the liquid hardenable resincomponent in an amount sufficient to consolidate the coatedparticulates. In some embodiments of the present invention, the resinutilized is included in the liquid hardenable resin component in therange of from about 70% to about 100% by weight of the liquid hardenableresin component.

Any solvent that is compatible with the hardenable resin and achievesthe desired viscosity effect is suitable for use in the presentinvention. Preferred solvents are those having high flash points (mostpreferably about 125° F.) because of, inter alia, environmental factors.As described above, use of a solvent in the hardenable resin compositionis optional but may be desirable to reduce the viscosity of thehardenable resin component for a variety of reasons including ease ofhandling, mixing, and transferring. It is within the ability of oneskilled in the art with the benefit of this disclosure to determine ifand how much solvent is needed to achieve a suitable viscosity. Solventssuitable for use in the present invention include, but are not limitedto, butylglycidyl ethers, dipropylene glycol methyl ethers, dipropyleneglycol dimethyl ethers, dimethyl formamides, diethyleneglycol methylethers, ethyleneglycol butyl ethers, diethyleneglycol butyl ethers,propylene carbonates, methanols, butyl alcohols, d'limonene and fattyacid methyl esters.

Examples of the hardening agents that can be utilized in the liquidhardening agent component of the low-temperature epoxy-based resinsinclude, but are not limited to, amines, aromatic amines, polyamines,aliphatic amines, cyclo-aliphatic amines, amides, polyamides,2-ethyl-4-methyl imidazole and 1,1,3-trichlorotrifluoroacetone.Selection of a preferred hardening agent depends, in part, on thetemperature of the formation in which the hardening agent will be used.By way of example and not of limitation, in subterranean formationshaving a temperature from about 60° F. to about 250° F., amines andcyclo-aliphatic amines such as piperidine, triethylamine,N,N-dimethylaminopyridine, benzyldimethylamine,tris(dimethylaminomethyl) phenol, and 2-(N₂N-dimethylaminomethyl)phenolare preferred with N,N-dimethylaminopyridine most preferred. Insubterranean formations having higher temperatures, 4,4-diaminodiphenylsulfone may be a suitable hardening agent. The hardening agent utilizedis included in the liquid hardening agent component in an amountsufficient to consolidate the coated particulates. In some embodimentsof the present invention, the hardening agent used is included in theliquid hardenable resin component in the range of from about 40% toabout 60% by weight of the liquid hardening agent component.

The silane coupling agent may be used, inter alia, to act as a mediatorto help bond the resin to the formation particulate surfaces. Examplesof silane coupling agents that can be utilized in the liquid hardeningagent component of the low-temperature epoxy-based resins include, butare not limited to, n-2-(aminoethyl)-3-aminopropyltrimethoxysilane,3-glycidoxypropyltrimethoxysilane, andn-beta-(aminoethyl)-gamma-aminopropyl trimethoxysilane. The silanecoupling agent used is included in the liquid hardening agent componentin an amount capable of sufficiently bonding the resin to the formationparticulates. In some embodiments of the present invention, the silanecoupling agent used is included in the liquid hardenable resin componentin the range of from about 0.1% to about 3% by weight of the liquidhardening agent component.

Any surfactant compatible with the liquid hardening agent may be usedwith the low-temperature epoxy-based resins. Such surfactants include,but are not limited to, ethoxylated nonyl phenol phosphate esters,mixtures of one or more cationic surfactants, and one or more non-ionicsurfactants and alkyl phosphonate surfactants. The mixtures of one ormore cationic and nonionic surfactants are described in U.S. Pat. No.6,311,773, the relevant disclosure of which is incorporated herein byreference. A C₁₂–C₂₂ alkyl phosphonate surfactant is preferred. Thesurfactant or surfactants utilized are included in the liquid hardeningagent component in an amount in the range of from about 2% to about 15%by weight of the liquid hardening agent component.

A diluent or liquid carrier fluid in the hardenable resin compositionmay be used to reduce the viscosity of the hardenable resin componentfor ease of handling, mixing and transferring. It is within the abilityof one skilled in the art, with the benefit of this disclosure, todetermine if and how much liquid carrier fluid is needed to achieve aviscosity suitable to the subterranean conditions. Any suitable carrierfluid that is compatible with the hardenable resin and achieves thedesired viscosity effects is suitable for use in the present invention.The liquid carrier fluids that can be utilized in the liquid hardeningagent component low-temperature epoxy-based resins preferably includethose having high flash points (most preferably above about 125° F.).Examples of liquid carrier fluids suitable for use in the presentinvention include, but are not limited to, dipropylene glycol methylethers, dipropylene glycol dimethyl ethers, dimethyl formamides,diethyleneglycol methyl ethers, ethyleneglycol butyl ethers,diethyleneglycol butyl ethers, propylene carbonates, d'limonene andfatty acid methyl esters.

Another consolidation material suitable for use in the methods of thepresent invention is a furan-based resin. Suitable furan-based resinsinclude, but are not limited to, furfuryl alcohol resins, mixturesfurfuryl alcohol resins and aldehydes, and a mixture of furan resins andphenolic resins. A furan-based resin may be combined with a solvent tocontrol viscosity, if desired. Suitable solvents for use in thefuran-based consolidation fluids of the present invention include, butare not limited to 2-butoxy ethanol, butyl acetate, and furfurylacetate.

Another consolidation material suitable for use in the methods of thepresent invention is a phenolic-based resin. Suitable phenolic-basedresins include, but are not limited to, terpolymers of phenol, phenolicformaldehyde resins, and a mixture of phenolic and furan resins. Aphenolic-based resin may be combined with a solvent to control viscosityif desired. Suitable solvents for use in the phenolic-basedconsolidation fluids of the present invention include, but are notlimited to butyl acetate, butyl lactate, furfuryl acetate, and 2-butoxyethanol.

Another consolidation material suitable for use in the methods of thepresent invention is a HT epoxy-based resin. Suitable HT epoxy-basedcomponents include, but are not limited to, bisphenol A-epichlorohydrinresins, polyepoxide resins, novolac resins, polyester resins, glycidylethers and mixtures thereof. An HT epoxy-based resin may be combinedwith a solvent to control viscosity if desired. Suitable solvents foruse with the HT epoxy-based resins of the present invention are thosesolvents capable of substantially dissolving the HT epoxy-resin chosenfor use in the consolidation fluid. Such solvents include, but are notlimited to, dimethyl sulfoxide, dimethyl formamide, dipropylene glycolmethyl ether, dipropylene glycol dimethyl ether, diethylene glycolmethyl ether, ethylene glycol butyl ether, diethylene glycol butylether, propylene carbonate, d'limonene, and fatty acid methyl esters.

Yet another consolidation material suitable for use in the methods ofthe present invention is a phenol/phenol formaldehyde/furfuryl alcoholresin comprising from about 5% to about 30% phenol, from about 40% toabout 70% phenol formaldehyde, from about 10 to about 40% furfurylalcohol, from about 0.1% to about 3% of a silane coupling agent, andfrom about 1% to about 15% of a surfactant. In the phenol/phenolformaldehyde/furfuryl alcohol resins suitable for use in the methods ofthe present invention, suitable silane coupling agents include, but arenot limited to, N-2-(aminoethyl)-3-aminopropyltrimethoxysilane,3-glycidoxypropyltrimethoxysilane, andn-beta-(aminoethyl)-gamma-aminopropyl trimethoxysilane. Suitablesurfactants include, but are not limited to, an ethoxylated nonyl phenolphosphate ester, mixtures of one or more cationic surfactants, and oneor more non-ionic surfactants and an alkyl phosphonate surfactant.Suitable solvents for use with phenol/phenol formaldehyde/furfurylalcohol resins include, but are not limited to, 2-butoxy ethanol, butylacetate, furfuryl acetate, and combinations thereof.

Regardless of the consolidation material chosen, its viscosity shouldpreferably be controlled to ensure that it is able to sufficientlypenetrate the subterranean formation. A preferred depth of treatment maybe from about one to about three well bore diameters; however, thelaminate and/or non-uniform makeup of the formation, i.e.shale-sandstone-shale-sandstone, etc., may make reaching such a depthunrealistic. In some embodiments of the present invention, theconsolidation fluid penetrates at least about 0.5 inches into the wallsof the well bore.

One embodiment of a method of the present invention provides a method ofdrilling a well bore with a drilling composition comprising a drillingfluid component and a consolidating material component, and allowing theconsolidating material to penetrate into the walls of the well bore.

Another embodiment of a method of the present invention provides amethod of consolidating a subterranean formation surrounding a well borecomprising the steps of drilling a well bore with a drilling compositioncomprising a drilling fluid component and a consolidating materialcomponent, and allowing the consolidating material to penetrate into thesubterranean formation surrounding the well bore.

Therefore, the present invention is well adapted to carry out theobjects and attain the ends and advantages mentioned as well as thosethat are inherent therein. While numerous changes may be made by thoseskilled in the art, such changes are encompassed within the spirit andscope of this invention as defined by the appended claims.

1. A method of drilling a well bore comprising the steps of: providing adrilling composition comprising a drilling fluid and a consolidatingmaterial, the consolidating material comprising a hardenable resincomponent that comprises a hardenable resin, and a liquid hardeningagent component that comprises a hardening agent, a silane couplingagent, and a surfactant; and using the drilling composition to drill atleast a portion of the well bore and allowing the consolidating materialin the drilling composition to penetrate into the walls of the wellbore.
 2. The method of claim 1 wherein the consolidating material has aviscosity of less than about 100 cP.
 3. The method of claim 1 whereinthe hardenable resin in the hardenable resin component is an organicresin selected from the group consisting of bisphenol A-epichlorohydrinresins, polyepoxide resins, novolak resins, polyester resins,phenol-aldehyde resins, urea-aldehyde resins, furan resins, urethaneresins, glycidyl ethers, and mixtures thereof.
 4. The method of claim 1wherein the hardening agent in the liquid hardening agent component isselected from the group consisting of amines, aromatic amines, aliphaticamines, cyclo-aliphatic amines, piperidine, triethylamine,benzyldimethylamine, N,N-dimethylaminopyridine,2-(N₂N-dimethylaminomethyl)phenol, tris(dimethylaminomethyl)phenol, andmixtures thereof.
 5. The method of claim 1 wherein the silane couplingagent in the liquid hardening agent component is selected from the groupconsisting of N-2-(aminoethyl)-3-aminopropyltrimethoxysilane,3-glycidoxypropyltrimethoxysilane, n-beta-(aminoethyl)-gamma-aminopropyltrimethoxysilane and mixtures thereof.
 6. The method of claim 1 whereinthe surfactant in the liquid hardening agent component is selected fromthe group consisting of ethoxylated nonyl phenol phosphate esters,mixtures of one or more cationic surfactants, C₁₂–C₂₂ alkyl phosphonatesurfactants, mixtures of one or more non-ionic surfactants and alkylphosphonate surfactants, and mixtures thereof.
 7. The method of claim 1wherein the hardenable resin is a furan-based resin is selected from thegroup consisting of furfuryl alcohol, mixtures of furfuryl alcohol withaldehydes, mixtures of furan resin and phenolic resin, and mixturesthereof.
 8. The method of claim 1 wherein the hardenable resin componentfurther comprises a solvent selected from the group consisting of2-butoxy ethanol, butyl acetate, furfuryl acetate, and mixtures thereof.9. The method of claim 1 wherein the consolidating material furthercomprises a phenolic-based resin selected from the group consisting ofterpolymers of phenol, phenolic formaldehyde resin, mixtures of phenolicand furan resin, and mixtures thereof.
 10. The method of claim 9 whereinthe consolidating material further comprises a solvent selected from thegroup consisting of butyl acetate, butyl lactate, furfuryl acetate,2-butoxy ethanol, and mixtures thereof.
 11. The method of claim 1wherein the consolidating material further comprises a HT epoxy-basedresin selected from the group consisting of bisphenol A-epichlorohydrinresins, polyepoxide resins, novolac resins, polyester resins, glycidylethers, and mixtures thereof.
 12. The method of claim 11 wherein theconsolidating material further comprises a solvent selected from thegroup consisting of dimethyl sulfoxide, dimethyl formamide, dipropyleneglycol methyl ether, dipropylene glycol dimethyl ether, dimethylformamide, diethylene glycol methyl ether, ethylene glycol butyl ether,diethylene glycol butyl ether, propylene carbonate, d-limonene, fattyacid methyl esters, and mixtures thereof.
 13. The method of claim 1wherein the consolidating material comprises: from about 5% to about 30%phenol; from about 40% to about 70% phenol formaldehyde; from about 10to about 40% furfuryl alcohol; from about 0.1% to about 3% of a silanecoupling agent; and from about 1% to about 15% of a surfactant.
 14. Themethod of claim 13 wherein the consolidating material further comprisesa solvent selected from the group consisting of 2-butoxy ethanol, butylacetate, furfuryl acetate, and combinations thereof.
 15. The method ofclaim 1 wherein the fluid component of the drilling fluid is an aqueousgel or an emulsion.
 16. The method of claim 1 wherein the consolidatingmaterial penetrates into the walls of the well bore from about 0.1 toabout 3 inches.
 17. The method of claim 1 wherein the drillingcomposition further comprises a fluid loss control material.
 18. Themethod of claim 17 wherein the fluid loss control material is selectedfrom the group consisting of aliphatic polyesters, polylactic acid,poly(lactides), and combinations thereof.